Downhole apparatus and method

ABSTRACT

A method of conditioning a well bore featuring an annulus ( 50 ) between a bore-lining tubing ( 20 ) and a surrounding bore wall ( 110 ) comprises pumping conditioning fluid through an inner tubing ( 10 ) located within the bore-lining tubing ( 20 ) and into a portion of the well bore containing the bore-lining tubing to affect the temperature of the portion of the well bore containing the bore-lining tubing. The annulus ( 50 ) between the bore-lining tubing ( 20 ) and the surrounding bore wall ( 110 ) is at least partially filled with settable material ( 54 ). The affected temperature of the portion of the well bore containing the bore-lining tubing influences the setting of the settable material. For example, heating the bore may accelerate setting of the material, while cooling the bore may retard setting of the material.

FIELD

This disclosure relates to downhole apparatus and downhole methods. Theapparatus and methods may be utilised in downhole operations involvingthe delivery and curing or hardening of settable materials, such ascement slurry.

BACKGROUND

In the oil and gas industry boreholes or well bores may be drilled inthe earth to access subsurface hydrocarbon-bearing formations. Thedrilled boreholes are typically lined with metal tubing, often referredto as casing or liner. The annulus between the bore-lining tubing andthe surrounding bore wall may be filled with a settable material,typically a cement slurry, which hardens to provide support for the borewall and the tubing. The hardened material may also restrict or preventmigration of fluid through the annulus, for example from a formationcontaining fluid at higher pressure into a lower pressure formation.

The cement slurry may be prepared on surface and then pumped down intothe bore. In many instances, the slurry is pumped down through thebore-lining tubing and then passes through the end of the tubing and upinto the surrounding annulus. A displacement fluid is pumped into thetubing behind the slurry and pushes the cement slurry into and upthrough the annulus. The pumping operation is continued until the slurryfills the annulus, or at least occupies a predetermined volume of theannulus. Several thousand metres of annulus may be cemented in a singleoperation.

As will be appreciated, cementing operations are technically challengingand complex, and many factors must be taken into consideration. It isgenerally considered desirable for the cement slurry to hardenrelatively quickly. However, a cementing operation may take many hoursto complete, and it is of course essential that the lead portion ofcement remains in a fluid condition long enough to pass down into theborehole and then up through the annulus to the desired fill level.Cement slurry formulations (cement recipes) are typically complexmixtures of mix-water, Portland cement and chemical additives. Thecement slurry setting time is tailored as a function of the geo-thermalgradient of the bore hole and the pump time. In areas where thegeo-thermal gradient is non-linear, contains hot zones, or isunpredictable (new exploration area), additional pump time is added tothe desired setting time as an additional pumping time safety factor.This additional safety factor greatly extends the cement setting timeand can lead to delays of subsequent operations.

In general, settable materials cure or harden more rapidly at highertemperatures. In U.S. Pat. No. 3,103,973 to Mullen, it is proposed toinject a heat-generating solution into an earthen cavity in or adjacentto which cementing is to be done. In one described example, anacid-sodium hydroxide mixture is pumped into a casing, separated from anaqueous cement slurry by a rubber plug. Water is pumped into the casingabove the acid-sodium hydroxide mixture until the rubber plug hasreached the bottom of the casing and the cement slurry has been forcedoutwardly around the lower end of the casing and has filled the annulusbetween the casing and the well bore. At this point the acid-sodiumhydroxide mixture is on the inside of the casing directly opposite thecement slurry so that heat being liberated from the mixture is conductedthrough the casing and maintains the temperature of the cement slurryhigher than the temperature would have been in the absence of theaqueous acid-sodium hydroxide solution. This method is proposed as beinguseful when operating in higher altitudes and latitudes, such as theCanadian permafrost region.

US Patent Application publication no US 2005/0194190 to Becker et al.discloses use of an electric heating tool which can be lowered into anoil well to apply heat at a precise depth to provide localized heatingof a fresh cement slurry to accelerate curing. The drawings illustratethe heating tool being used to heat the tail cement portion at thebottom of the well bore.

SUMMARY

The present disclosure provides a method of conditioning a well borefeaturing an annulus between a bore-lining tubing and a surrounding borewall, the method comprising pumping conditioning fluid through an innertubing within the bore-lining tubing, and into a portion of the wellbore containing the bore-lining tubing, at least one feature of theconditioning fluid being controlled to affect the temperature of theportion of the well bore containing the bore-lining tubing, and at leastpartially filling the annulus between the bore-lining tubing and thesurrounding bore wall with settable material, whereby the affectedtemperature of the portion of the well bore containing the bore-liningtubing influences the setting rate of the settable material.

In another example, the at least one feature of the conditioning fluidis controlled such that the affected temperature of the portion of thewell bore containing the bore-lining tubing influences the dimensions ofthe bore-lining tubing. In such an example, the conditioning fluid maybe pumped into the well bore before or after at least partially fillingthe annulus between the bore-lining tubing and the surrounding bore wallwith settable fluid.

The at least one feature of the conditioning fluid may be controlled byan operator to raise or lower the temperature of the portion of the wellbore containing the bore-lining tubing.

The conditioning fluid may be pumped into a volume adjacent thebore-lining tubing to affect the temperature of the portion of thebore-lining tubing adjacent the volume. The affected temperature of thebore-lining tubing may at least one of influence the setting rate of thesettable material in at least the portion of the annulus adjacent thevolume and influence the dimensions of the bore-lining tubing.

The disclosure also relates to an apparatus for conditioning a wellbore. In one example, the apparatus comprises a tubular body formounting on an inner tubing string, a first flow port, a second flowport, and a third flow port, and a connector operatively associated withthe tubular body and operable to at least one of engage with anddisengage from a lower end of a bore-lining tubing string, the apparatushaving a first configuration in which the first flow port is open andthe second and third flow ports are closed, whereby a settable materialmay be pumped in a first direction downwards through the tubular body,the connector, and the first flow port, and a second configuration inwhich the first flow port is closed and at least one of the second andthird flow ports is open, whereby a conditioning fluid may be pumped inthe first direction down through the tubular body, through the at leastone of the second and third flow ports, and then flow in a seconddirection upwards and externally of the tubular body.

Conditioning fluid may be pumped into the portion of the well borecontaining the bore-lining tubing before the step of at least partiallyfilling the annulus between the bore-lining tubing and the surroundingwell bore with settable material. Alternatively, conditioning fluid maybe pumped into the portion of the well bore containing the bore-liningtubing after the step of at least partially filling the annulus betweenthe bore-lining tubing and the surrounding well bore with settablematerial. Accordingly, the conditioning fluid may be directed into aninternal volume of the bore-lining tubing. Furthermore, the conditioningfluid may be pumped into the volume within the bore-lining tubing, afterpart-filling the annulus between the bore-lining tubing and thesurrounding well bore with settable material and before further fillingthe annulus between the bore-lining tubing and the surrounding well borewith settable material.

Conditioning fluid may be pumped into the annulus between thebore-lining tubing and the surrounding well bore.

A predetermined volume of conditioning fluid may be pumped into theportion of the well bore containing the bore-lining tubing and then leftin the well bore for a predetermined time interval. Alternatively, or inaddition, conditioning fluid may be circulated through the bore-liningtubing. Fluid displaced from the well bore by the conditioning fluid mayflow out of an upper end of the bore-lining tubing.

The conditioning fluid may be utilised to cool at least a portion of thewell bore. Alternatively, or in addition, the conditioning fluid may beutilised to heat at least a portion of the well bore. Furthermore, theconditioning fluid may be utilised to maintain at least a portion of thewell bore at a predetermined temperature, or within a predeterminedtemperature range.

The conditioning fluid may be cooled to below ambient temperature beforebeing pumped into the well bore. In this case, ambient temperature maybe the ambient air temperature near the pump for pumping theconditioning fluid, or the ambient air temperature near other associatedequipment, for example the ambient air temperature around a drilling rigor on a ship. Alternatively, ambient temperature may be the seatemperature in the vicinity of a drilling rig or ship or may be thesurface sea temperature or the temperature at the sea floor.Alternatively, or in addition, the conditioning fluid may be heated toabove ambient temperature before being pumped into the well bore. Thetemperature of the conditioning fluid may be varied over the course of acementing operation.

The conditioning fluid may comprise materials which reactexothermically, which reaction may increase the temperature of thefluid, or the conditioning fluid may comprise materials which react tolower the temperature of the fluid.

The conditioning fluid may flow from the inner tubing directly into aselected volume within the bore-lining tubing. For example, theconditioning fluid may flow directly from the inner tubing into: a lowerlocation within the bore-lining tubing; one or more intermediatelocations within the bore-lining tubing, or an upper location within thebore-lining tubing. Of course, the well bore may be inclined orhorizontal, in which case the locations may be described as distal,intermediate or proximal locations. The conditioning fluid may flowdirectly into selected volumes within the bore-lining tubing in apredetermined sequence, for example the fluid may flow directly into anupper location, and then into one or more intermediate locations, andthen into a lower location.

The inner tubing may be provided in association with one or more flowports or fluid outlets providing fluid communication between theinterior of the inner tubing and the annulus between the bore-liningtubing and the surrounding bore wall. Alternatively, or in addition, theinner tubing may be provided with one or more flow ports or fluidoutlets providing fluid communication between the interior of the innertubing and a volume or inner annulus between the bore-lining tubing andthe inner tubing. The fluid outlets may be provided at a single locationor at spaced locations along the length of the inner tubing, for examplea fluid inlet may be provided towards a distal end of the tubing, one ormore fluid outlets may be provided intermediate the ends of the tubing,and a fluid outlet may be provided towards a proximal end of the tubing.One or more of the fluid outlets may be provided with a valve operableto control flow of fluid through the outlets. Where a plurality ofvalves is provided the valves may be operated individually, or one ormore valves may be operated in unison. The valves may be operated by anyappropriate mechanism or control, for example by tubing pressure, bylanding a closing device or an operating device such as a ball or dartin the valve, or by pumping RFID tags to initiate operation of thevalve. The valves may be provided with burst discs or the like or mayinclude sliding valve members. Any valves controlling flow ofconditioning fluid between the interior of the inner tubing and theinner annulus may be initially closed and may be opened under operatorcontrol to permit flow from the inner tubing into the inner annulus. Thevalves may be subsequently closed.

The settable material may be delivered to an annulus between thebore-lining tubing and the bore wall via the inner tubing.

An inner annulus between the bore-lining tubing and the inner tubing maybe closed at an upper or proximal end. A flow control device may beprovided to control flow of fluid from the upper or proximal end of theinner annulus. Fluid flowing through the flow control device may havebeen displaced from the inner annulus by the conditioning fluid or maybe conditioning fluid that has been circulated through the innerannulus.

The conditioning fluid may be utilised to maintain or increase thetemperature of the settable material and may thus accelerate the settingor curing of the settable material. The conditioning fluid may bedirected to accelerate the setting of the settable material at aselected location in the well bore. For example, the conditioning fluidmay be utilised to accelerate the setting of cement in the portion ofthe annulus between the lower or distal end of bore-lining tubing andthe surrounding bore wall, at any selected zone of interest, or indeedacross the whole annulus. The acceleration of the setting may acceleratecompressive strength generation or build-up and may reduce wait oncement (WOC) time before operations, for example drilling, may continuein the well bore. In an alternative example, the conditioning fluid maybe utilised to accelerate the setting of cement in an upper end portionof the annulus, to facilitate support of other apparatus mounted on theupper end of the bore-lining tubing, such as a blowout preventer (BOP).Characteristics of a settable material may vary with setting temperatureor setting time. For example, some cements may set to provide a highercompressive strength if the temperature of the setting cement isincreased.

The conditioning fluid may be utilised to increase the temperature of atleast a part of the portion of the well bore containing the bore liningtubing by 5° C. or more, 10° C. or more, 15° C. or more, 20° C. or more,25° C. or more, 30° C. or more, 35° C. or more, or 40° C. or more.

The conditioning fluid may be utilised to maintain or decrease thetemperature of the settable material to stop, slow or extend thethickening or curing time of the settable material. For example, thewell bore temperature may be reduced to extend a time interval or windowavailable to ensure that the settable material may be circulated intothe annulus. This may be particularly advantageous in deep or hot wells.Furthermore, the properties of some settable materials, such as someforms of Portland cement, may be adversely affected by setting atelevated temperatures. Thus, it may be advantageous to utilise theconditioning fluid to reduce the well bore temperature at least one ofbefore and after placing the settable material in the annulus topreserve the desirable properties of the set material. It has also beenestablished that, as the setting temperature increases, the sensitivityof Portland cement systems to subtle chemical and physical differencesbetween the slurry ingredients also increases. Thus, cooling the wellbore before or following circulating the settable material may providefor more predictable cement behaviour.

The conditioning fluid may also be utilised to selectively cool aselected location of the well bore. For example, in a longer, deep borethere may be a significant temperature differential between the upper,cooler end of the bore and the lower, hotter end of the bore. The lowerend of the bore may thus be cooled to facilitate circulation of thesettable material into the annulus, without unnecessarily retardingsetting of the material once it is in place in the upper end of thebore. Furthermore, in the absence of cooling a lower portion of the wellbore, the temperature profile of the well bore will tend to result inthe settable material hardening from the hotter, lower end of the boreupwards, which may not provide optimum conditions in the annulus.

The conditioning fluid may be utilised to provide temperature control ofthe settable material and thus control the transition of the settablematerial from a fluid form to a solid, and the final form of the setmaterial. For example, temperature is one of the major factors affectingthe hydration rate of Portland cement, and thus may impact on thenature, stability and morphology of the hydration products. Further, inthe initial liquid or slurry form, the column of cement in the annulusmay provide a significant hydrostatic head and thus be effective inretaining fluid in formations intersected by the well bore, and thusrestrict or prevent fluid migration into or along the annulus. As thegel strength of the static settable material increases, the hydrostatichead provided by the material may decrease. Thus, by suppressing thetemperature of the bore, and thus the temperature of the settablematerial, it may be possible to maintain a hydrostatic overbalance for alonger time.

The conditioning fluid may be utilised to create a selected thermalgradient across a portion of the length of the well bore, therebyproviding a degree of control over the transition of the settablematerial from fluid to solid form, which may relate to the rate of gelstrength increase. Transition time may be referred to as time from whichthe static gel strength (SGS) of a cement goes from 100 lbf/100 sq. ft(48 Pa) to 500 lbf/100 sq. ft (240 Pa). It has become an industrystandard that once cement slurries reach an SGS of 500 lbf/100 sq. ft(240 Pa)., gas or other fluids cannot be transmitted through the cement.Thus, the faster an operator brings the cement through this transitionzone (i.e. from an SGS of 100 lbf/100 sq. ft (48 Pa) to 500 lbf/100 sq.ft (240 Pa)), the sooner this optimum SGS is achieved, and the lesslikely that the cement will transmit gas or other fluids. However, asnoted above, an increase in gel strength may be accompanied by areduction in the hydrostatic head provided by the column of cement, anda decrease in the pressure available to prevent higher pressure fluidfrom escaping from a formation. Using the method of the presentdisclosure the operator may control where and when cement slurry goesthrough the transition zone. In one example, the operator may controlthe temperature in the well bore such that the portion of cement slurrygoing through the transition zone is effectively translated through thewell bore, typically from a lower portion of the well bore towards anupper portion of the well bore. In this situation an upper portion ofthe cement slurry may remain in a relatively fluid state while a lowerportion transitions towards a solid state, thereby maintaining thehydrostatic pressure effect of the slurry above the hardening cement.This effect may be achieved by circulating heated conditioning fluid ata calculated controlled rate through a selected portion of the wellbore. The conditioning fluid may be directed through a selected flowport into a selected volume of the well bore, heating the adjacentbore-lining tubing and settable material. The heated conditioning fluidwill progress up through the volume between the inner tubing and thebore-lining tubing at the controlled rate to create a thermal gradientacross the length of the portion of the bore-lining tubing and thesettable material. The volume of settable material adjacent to theselected flow port will experience the earliest heating, and thus willtend to be the first volume of material to harden. As the heatedconditioning fluid moves up through the bore the adjacent settablematerial will experience a corresponding rise in temperature, and thesettable material will thus harden as the heated conditioning fluidprogresses up through the well bore, while an upper portion of thesettable material remains in a fluid form and continues to provide ahydrostatic pressure force and overbalance to retain fluid in theadjacent earthen formations while the lower portions of cement harden.

This feature may be particularly useful where a bore intersects aformation containing higher pressure fluid at a relatively shallowdepth. Using a similar process to that described above, the operator mayaccelerate setting of cement directly adjacent the formation to achievean SGS sufficient to prevent passage of fluid from the formation. Asthis volume of cement goes through the transition zone there will beloss of hydrostatic head, but this loss will be restricted to thetargeted volume of cement and the cement above the targeted volume maybe retained in fluid form until the fluid is safely retained by the setcement adjacent the formation. Conventional techniques for dealing withthese situations include managed pressure cementing, complex slurrytrains and expensive additives, which can add very significant costs tothe cementing operation.

Similarly, an operator may prefer that only a part of the settablematerial is setting, or in a transition phase, at any point in time. Forcertain materials this may be achieved by utilising the conditioningfluid to maintain the well bore at or below a predetermined temperature.This may be achieved by, for example, circulating cooled or unheatedconditioning fluid through the well bore before introducing the settablematerial. Alternatively, or in addition, once the settable material isin place, conditioning fluid may be circulated to maintain the well boreat a lower temperature, thus halting or slowing hydration, curing orsetting of the material.

The curing or hardening of the settable material may generate heat. ForPortland cement, this may be termed the heat of hydration. This heat mayhave numerous effects, including autoacceleration of hydration and thethermal expansion of a metallic bore-lining tubing. On subsequentcooling, the bore-lining tubing may shrink, circumferentially andaxially, to a greater degree than the surrounding settable material, anda gap, which may be referred to as a thermal micro-annulus, may appearbetween an outer surface of the bore-lining tubing and the inner surfaceof the set material, compromising zonal isolation. Furthermore, in deepsubsea well bores, the seabed may feature hydrates, that is natural gasmolecules which are trapped in ice molecules, and if the seabed isheated the hydrates may be released, risking collapse of the seabed andrelease of large volumes of flammable gas. In such situations, theconditioning fluid may be utilised to reduce the temperature of the wellbore to, for example, reduce or avoid autoacceleration of hydration,minimise thermal expansion of the bore-lining tubing, or minimiseheating of the surrounding earth to prevent or reduce release ofhydrates.

The conditioning fluid may be utilised to influence one or moredimensions of the bore-lining tubing, such as influencing thecircumferential dimension of the tubing or the axial dimension of thetubing. For example, the conditioning fluid may be utilised to expandthe bore-lining tubing, contract the bore-lining tubing, or maintain thedimensions of the bore-lining tubing substantially constant. Thedimensions of the bore-ling tubing may be influenced by a number offactors, such as the heat of hydration of curing cement and the ambienttemperature in the well bore, which will tend to increase with depth.The relative pressure between the interior and the exterior of thebore-lining tubing may also impact on the dimensions of the tubing.These factors will have a varying impact and influence over time, forexample the heat of hydration will reduce as the cement cures, while thetemperature of the bore-lining tubing will likely rise from an initialtemperature when the tubing is initially run into the bore, or thetubing is surrounded by recently introduced and relatively cool cementslurry, to a temperature close to the surrounding earth formations. Thebore-lining tubing may also experience other temperature and pressurechanges subsequent the cementing operation, for example as fluid iscirculated through the bore-lining tubing during subsequent drillingoperations. Where there is differential expansion or contraction betweenthe bore-lining tubing and the surrounding set material there is anincreased risk of separation of the outer surface of the bore-liningtubing and the inner surface of the set material, and the formation of amicro-annulus, which impacts on the pressure integrity of the well bore.As will be described, in accordance with an aspect of the disclosure,the conditioning fluid may be utilised to control or influence theexpansion or contraction of the bore-lining tubing.

The conditioning fluid may be utilised to reduce the temperature of thebore-lining tubing, or at least reduce or control the rise intemperature of the bore-lining tubing due to other factors. This may beachieved by circulating conditioning fluid into the bore well prior toplacing settable material in the annulus, or by circulating conditioningfluid into the bore well after placing settable material in the annulus.

The conditioning fluid may be utilised to maintain the temperature ofthe bore-lining temperature below the ambient temperature of the wellbore while the settable material is hardening. Once the settablematerial has hardened the temperature of the bore-lining tubing may beallowed to rise to the ambient temperature of the well bore, which willbe accompanied by thermal expansion of the bore-lining tubing. Thisthermal expansion of the bore-lining tubing will be restrained by thesurrounding set material. This will close any existing micro-annulibetween the bore-lining tubing and the set material and will minimisethe risk of micro-annuli forming in future.

The temperature of fluids in a well bore may be measured or estimatedusing a variety of apparatus or models. Estimating the temperature ofconditioning fluid and cement slurry in a bore may utilise a computersimulation, such as the Wellbore Simulator (Trade Mark). Suchsimulations utilise known inputs such as cement volumes, bottom-holestatic temperature, geothermal gradient, sea temperature, sea-bedtemperature, sea current and the like. Similar tools may be utilised toestimate the changes in temperature experienced by conditioning fluidbeing pumped from a rig into a bore, and so determine the mostappropriate initial temperature for the conditioning fluid, and the mostappropriate flow rate of conditioning fluid. The supply of heated orcooled conditioning fluid into a bore will allow the operator to varythe temperatures and gradients within the bore which were previouslyconsidered constants, thus providing an additional degree of control andinfluence over the bore conditions.

The density of the conditioning fluid may be selected or varied tofacilitate provision of a predetermined pressure within the bore-liningtubing while the settable material hardens or cures. The internalpressure may be selected to control or influence pressure-relateddeformation of the bore-lining tubing, and in particular to minimisecreation of a micro-annulus between the bore-lining tubing and thehardened settable material. For example, the bore-lining tubing and thesettable material may contract by different degrees as Portlandcement-based slurry sets and cools, following initial hydration. Also,the settable material may shrink due to water loss into the surroundingearth formations, and the hydrostatic pressure exerted by the settablematerial on the bore-lining tubing may decrease as the material thickensand as the gel strength of the material increases. By selection of anappropriate density for the conditioning fluid, for example a lowerdensity, the bore-lining tubing may tend to describe a smaller diameterand be less likely to shrink subsequently and separate from thesurrounding cement.

The conditioning fluid, or a flushing fluid, may be utilised to conducta pressure test on the bore-lining tubing, which test may be conductedfollowing the circulation of the settable material into the annulusbetween the bore-lining tubing and the well bore, and prior to thesetting of the material. A plug may be dropped or pumped into a flowport in communication with the bore-lining tubing, or a valve closed, toisolate the conditioning fluid from the settable material in theannulus.

The bore-lining tubing may be provided with a shoe at a leading end ofthe tubing, which shoe may include a float valve that permits flow offluid from within the tubing to the exterior of the tubing, but whichrestricts or prevents reverse flow into the tubing. The bore-liningtubing may include a profile to engage with a connector provided at aleading or distal end of the inner tubing, which profile may beincorporated in a tubing or float shoe. The inner tubing connector mayinclude a cooperating profile. The distal end of the inner tubing may beconfigured for stabbing or latching engagement with the bore-liningtubing. Release of the inner tubing from the bore-lining tubing mayrequire rotation, for example to back out a threaded connection. A firstflow port providing fluid communication between the interior of theinner tubing and the exterior of the bore-lining tubing may be providedin the float shoe or may be provided in the connector.

The inner tubing may include a coupling portion which permits selectivetransmission of torque between portions of the inner tubing. In oneconfiguration torque may be transferred from a proximal end of the innertubing to a distal end of the inner tubing, for example to allowcoupling or uncoupling of a threaded connector. In anotherconfiguration, a proximal end of the inner tubing may be rotated withouttransfer of the rotation to the distal end of the tubing. Such acoupling portion may be configured to allow rotation of an upper portionof the inner tubing to permit engagement or disengagement of threadedcouplings above the coupling portion without affecting threadedcouplings below the coupling portion. The coupling portion may betelescopic and feature a spline arrangement in which the couplingportion may be extended to engage the spline arrangement and compressedto disengage the spline arrangement. The coupling portion may be made inaccordance with the teaching of UK Patent Applications GB2525148A andGB2545495A, the disclosures of which are incorporated herein in theirentirety.

An upper or proximal end of the bore-lining tubing may be sealed, forexample such that the volume or inner annulus between the inner tubingand the bore-lining tubing may be pressurised. A flow port may beprovided to allow fluid to be circulated from or into the volume. Theflow port may be provided with a valve to control flow from or into thevolume.

The inner tubing and the bore-lining tubing may be provided incombination with running apparatus to facilitate location of the tubingin a well bore from a surface rig. The running apparatus may comprise arunning string and a running tool. The running tool may provide a sealtowards an upper or proximal end of the bore-lining tubing. The runningtool and the bore-lining tubing may be provided with cooperatingprofiles, for example cooperating threads. In one example, the runningtool may engage the bore-lining tubing via a left-handed thread.

The running string may be insulated or otherwise configured to minimiseheat loss or gain from fluid passing through the string. A conventionalrunning string is likely to be formed of steel tubing, such as drillpipe. Thus, for example, if the running string extends from surfacethrough several thousand meters of cold sea water, hot water beingpumped at pressure through the string will experience significant heatloss between the rig and the sea bed. Insulating material, such as afoamed material, may be provided around the exterior of a conventionalstring, an inner conduit of non-metallic material may be provided tocarry the fluid through the metallic string, or the string may extendthrough a larger string, such as a riser, to minimise heat loss. Inother examples a heating element may be provided in or associated withthe string.

The bore-lining tubing may take any appropriate form and may be, forexample, casing, liner, or completion tubing. The bore-lining tubing maybe formed of any suitable material but will typically be metallic andmay steel or another alloy. Casing and liner may be formed from tubularjoints provided with male threaded end portions which are coupled usingexternal female threaded connectors. In this document the term “casing”may be used as a reference to bore-lining tubing in general, and shouldnot be interpreted to exclude liner or other forms of bore-liningtubing.

The bore wall surrounding the bore-lining tubing may be formed of theearthen wall of the drilled well bore or may be formed, at least inpart, by another bore-lining tubing, for example an existing casingsection.

The inner tubing may take any appropriate form and may comprise an innerstring, a major portion of which may be formed of drill pipe. A drillpipe string may comprise multiple drill pipe joints, typically eachjoint having an externally threaded pin connection at a lower end and aninternally threaded box connection at an upper end.

Portions of the inner tubing may be insulated to minimise heat transferfrom fluid passing through the tubing to surrounding fluid.Alternatively, or in addition, the inner tubing may be formed of anon-metallic material or include a non-metallic inner wall. Thenon-metallic material may be a composite selected to be less heatconductive than metal tubing.

The inner tubing may be coaxial with the bore-lining tubing, may belocated to one side of the bore-lining tubing, or may have a helicalform. The inner tubing may not be subject to substantial loading and maytherefore comprise a relatively lightweight material, such as anextruded or pultruded composite.

The conditioning fluid may take any appropriate form and may be, forexample, water, brine, seawater or drilling fluid.

The settable material may take any appropriate form and may comprisecement slurry, grout, epoxy or a two-component material that hardensfollowing mixing of the components. If the settable material is cementslurry, the cement may be of any appropriate formulation suitable forthe well bore conditions. The cement slurry may comprise a Portlandcement.

Heating or cooling apparatus may be provided for heating or cooling theconditioning fluid. The heating or cooling apparatus may be provided ona drilling rig or ship. The heating or cooling apparatus may take anyappropriate form and may comprise a heat exchanger.

In another aspect, the present disclosure provides a method ofconditioning a well bore featuring an annulus between a bore-liningtubing and a surrounding bore wall, the method comprising pumpingconditioning fluid through an inner tubing located within thebore-lining tubing and into a portion of the well bore containing thebore-lining tubing to affect the temperature of the portion of the wellbore containing the bore-lining tubing, and at least partially fillingthe annulus between the bore-lining tubing and the surrounding bore wallwith settable material, whereby the affected temperature of the portionof the well bore containing the bore-lining tubing influences thesetting of the settable material.

In another aspect, the disclosure provides an apparatus for conditioninga well bore, the apparatus comprising a tubing string for locationwithin bore-lining tubing and having a lower end portion for coupling tothe bore-lining tubing and a plurality of flow ports at spaced locationsalong the tubing string, wherein the valves are initially closed and areopenable to permit fluid to be flowed from the tubing string and out ofthe flow ports.

A further aspect of the disclosure relates to a settable materialsampling method comprising: pumping settable material into a well boreannulus surrounding a bore-lining tubing string via an inner tubingstring located within the bore-lining tubing string; retaining a volumeof the settable material in a lower end of the inner tubing string;allowing the volume of settable material to set; retrieving the innertubing string from the well bore; and removing the volume of setmaterial from the inner tubing string.

The method may be utilised in combination with one or more of the othermethods described herein.

The volume of set material will have experienced similar flow andsetting conditions to the settable material in the annulus. Thus,testing of the volume of set material will provide an indication of thefeatures and qualities of the settable material in the annulus.Conventionally, small volumes of settable material are collected atsurface and allowed to set at surface ambient conditions. These samplesare then subject to testing. However, given the very differentconditions experienced by the settable material in the annulus, thesurface samples will be unlikely to provide an accurate representationof the features and qualities of the material that has set in theannulus.

The volume of settable material may be allowed to set in the well bore.The volume of settable material may be allowed to set while otheroperations are carried out, for example flushing residual settablematerial from the inner tubing string above the volume or circulatingconditioning fluid through the well bore to control or modify thesetting of the material in the annulus. The volume of settable materialmay be allowed to set before the inner tubing string is disconnectedfrom the bore-lining tubing string. In other examples the volume ofsettable material may be allowed to set as the inner tubing string isretrieved from the well bore, or once the inner tubing string has beenretrieved to surface.

The degree of setting of the settable material may be selected dependingon the nature of tests to be conducted on the sample. In one example thesetting time for a volume of cement slurry may be calculated as the timesufficient for the static gel strength (SGS) of the cement to reach orexceed 500 lbf/100 sq. ft (240 Pa).

The method may comprise providing a flow barrier in a lower end of theinner tubing string, whereby the settable material in the inner tubingstring above the barrier is retained in the inner tubing string when theinner tubing string is disconnected from the bore-lining tubing string.The flow barrier may be a dart or a ball or may be a valve member. Theflow barrier may be pumped or dropped into place.

The method may comprise at least one of pumping displacement fluid,flushing fluid or conditioning fluid behind the settable material, and abarrier such as a wiper dart may be provided between the settable fluidand the following fluid. Such a barrier may minimise contamination ofthe settable material by the following fluid.

The inner tubing string may be adapted to facilitate removal of thevolume of settable material. For example, the inner tubing string mayinclude a portion formed of separable parts or may include a portionincluding a polished or low friction surface or sleeve, to facilitateremoving a core of set material from the tubing string.

An aspect of the disclosure also relates to settable material samplingapparatus comprising a hollow body for mounting between an inner tubingstring and a bore-lining tubing string, and a flow barrier adapted toland in a lower portion of the hollow body to retain a volume ofsettable material in the hollow body when the hollow body isdisconnected from the bore-lining tubing string.

The apparatus may be provided in combination with the other apparatusdescribed herein.

Another aspect of the disclosure relates to a method for locating abore-lining tubing string in a bore hole, the method comprising:

a) engaging a lower end of an inner tubing string with a lower end of abore-lining tubing string;

b) pumping settable material down through the inner tubing string and afirst flow port at a lower end of the bore-lining tubing string suchthat the settable material flows into a first annulus between thebore-lining tubing string and a surrounding bore wall;

c) closing the first flow port;

d) opening a second flow port in the inner tubing string above the lowerend of the bore-lining tubing string;

e) pumping fluid down through the inner tubing string, out of the secondflow port and into a volume between the inner tubing string and thebore-lining tubing string, the fluid then flowing into the volumebetween the inner tubing string and the bore-lining tubing string; and

f) disengaging the lower end of the inner tubing string from the lowerend of the bore-lining tubing and retrieving the inner tubing stringfrom the bore hole.

The fluid may flow upwards through the volume between the inner tubingstring and the bore-lining tubing.

The disclosure also relates to an associated apparatus. In one example,the apparatus comprises a tubular body for mounting on an inner tubingstring, a first flow port, a second flow port, and a connectorassociated with the tubular body and operable to at least one of engagewith and disengage from a lower end of a bore-lining tubing string, theapparatus having a first configuration in which the first flow port isopen and the second flow port is closed, whereby a settable material maybe pumped in a first direction downwards through the tubular body,through the connector, and through the first flow port, and a secondconfiguration in which the first flow port is closed and the second flowport is open, whereby a fluid may be pumped in the first directiondownwards through the tubular body, exit the tubular body through thesecond flow port, and then flow in a second direction upwards andexternally of the tubular body.

According to a further aspect, the disclosure provides a work string foruse in a bore hole, the work string comprising: a conduit connectablebetween a lower portion of a casing or liner in the bore hole and a topportion of the casing or liner; the conduit for providing a first flowpath from the top portion to an outer side of the casing via the lowerportion; and a valve in an outer wall of the conduit for selectivelyproviding a second flow path between the conduit and an inner side ofthe casing or liner.

The valve in the conduit allows fluid to be pumped into an annulusdefined between an outside of the work string and an inner side of thecasing. The work string is typically used to pump a hardening fluid,such as cement, into an annulus defined between an outside of the casingand the walls of the borehole, so as to form hard walls (structuralsupport) for the borehole.

Having the valve allows a fluid to be pumped through the work string toflush out residual hardening fluid remaining in the work string. Thismixture of fluid and hardening fluid may then be flushed out from theinner side of the casing without disrupting the hardening fluid on theoutside of the casing.

The valve also allows for pressure testing of the casing (e.g. bypumping a fluid into the inner side of the casing) while the hardeningfluid is still in a flowable state.

This is advantageous because the pressure testing can cause the casingto expand outwards (to “balloon”) during the test and relax back afterthe test. If the hardening fluid is still in a liquid state, it willflow back around the casing after the pressure test, forming a goodconnection between borehole and casing. By contrast, if the hardeningfluid has already hardened, the pressure testing can cause cavities(weak points) when the casing relaxes back after testing.

The existence of the valve may also eliminate the need for an operatoror robot (e.g. ROV) at the wellhead. This can both save costs andeliminate a point of failure, e.g. robot malfunction, from the processof forming the well in the borehole.

The valve may comprise a shear disc having a predetermined rupturepressure. Alternatively, or additionally, the valve may comprise asliding valve having a sliding portion that selectively covers anduncovers a hole in the conduit. Multiple valves may be provided in thework string, as desired.

A shear disc covers an aperture in the work string that forms apurposely designed weak spot with a predetermined rupture pressure.Thus, the user can pump the hardening fluid at a pressure below thatrequired to rupture the shear disc or (pop it out from its housing) andthen can use a second fluid at a higher pressure to rupture the sheardisc and thus open the valve. This is a simple arrangement that does notrequire any solid connection (e.g. levers) between the valve and theoperator (which may be several hundred meters apart) and can be simplycontrolled by the pressure applied to the second fluid.

The sliding sleeve avoids introducing any debris into the fluid whenopening (e.g. a popped shear disc).

In some embodiments, one end of the conduit comprises an adapter forconnecting to the lower portion; and the valve may be formed in theadapter.

This allows the valve to be added to existing work strings whilst onlyrequiring modification of the adapter end and not to the rest of thework string.

The present disclosure may also provide a system for cementing aborehole, the system comprising: a casing extendable within the borehole, the casing defining an internal space and having an outer surface;and the work string as described above extending within the internalspace and connected to a lower portion of the casing and to a topportion of the casing.

According to a second aspect, the present invention provides a method ofusing a work string in a casing, the method comprising: connecting thework string to a lower portion of the casing via an adapter to allowfluid flow through the work string into the lower portion; pumping afirst fluid through the work string and through the lower portion to anoutside of the casing; closing an aperture in the lower portion; openinga valve in the work string to allow fluid flow into an annulus definedby the work string and an inside of the casing; and pumping a secondfluid through the work string and into the annulus.

Closing the aperture in the base portion allows the work string to beremoved before the hardening fluid cures.

In some known designs, the work string does not connect to a lowerportion of the casing at all but instead hangs above the lower portion.The hardening fluid is then pumped into the space inside the casing andthen is forced down through a one-way check-valve in the base of thecasing and into the annulus defined by the casing and borehole bypumping a second fluid into the space inside the casing (e.g. water).The one-way check-valve can leak if there is excessive pumping acrossthe valve. According to the present disclosure, a wiper dart can bedelivered via the work string to plug an aperture in the casing. Thismay eliminate the aforesaid failures of the check-valve. Further, thewiper dart can seal the flow path into the annulus and enable pressureto be built up within the work string in order to activate the valve.

The first fluid may be a fluid that hardens by curing. Preferably, thefirst fluid is cement.

In the method, the step of pumping the second fluid through the workstring may be begun before the first fluid hardens.

The work string may be removed before the hardening fluid has hardened,which can reduce WOC time (“Wait-on-cement” time).

The step of pumping may be for performing a step of pressure-testing thecasing before the first fluid hardens.

This allows for pressure testing that does not adversely affect thestrength of the wall formed in the borehole by the casing and hardenedfluid. Indeed, pressure testing while the hardening fluid is not yethardened may improve the interfacial adhesion between hardening fluidand casing, resulting in an improved wall of the borehole when thehardening fluid has hardened.

The step of pumping the second fluid may be to wash residual first fluidout the work string and into the annulus before the first fluid hardens.Optionally, this may include washing the residual first fluid out of thecasing via a top valve at an upper end of the casing (e.g. a valve inthe running tool, such as a ball-valve).

This prevents any hardening fluid from undesirably hardening within thework string which can damage the work string or make it non-reusable. Awork string is typically made from a number of component parts connectedtogether sequentially and it is generally undesirable to permanentlyattach two adjacent component parts with the hardening fluid.

The top valve is preferably formed in a wellhead to which the casing isconnected.

The pressure testing may comprise: pumping the second fluid into theannulus via the work string wherein the second fluid is water; anddetermining if a detected pressure-gradient is consistent with asufficiently sealed annulus. If the casing fails the pressure test atthe first step, the method may further comprise a step of: pumpingdrilling mud into the annulus via the work string; and determining if adetected pressure-gradient is consistent with a sufficiently sealedannulus.

The drilling mud is an engineering composition that has a fluid (e.g.water) and particulate matter suspended therein. The particulate mattercan plug small holes or cracks in the casing so as to repair said holeor crack. Thus, the present method allows both testing and repair of thecasing wall before the hardening fluid has hardened.

The various features described above may have utility when providedindividually or in combination with other features described herein,including the features as listed in the attached claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain features of the present disclosure will now be described ingreater detail by way of example only and with reference to theaccompanying drawings in which:

FIG. 1 shows a cross-sectional view of a work string extending within acasing that extends within a bore hole;

FIG. 2 shows the bore hole being filled with a settable material via thework string;

FIG. 3 shows a lower portion of the casing being plugged after the borehole has been filled with settable material; and

FIG. 4 shows a second fluid being pumped into the inside of the casingvia a valve in the work string;

FIG. 5 shows the bore hole after the work string and running tool havebeen removed; and

FIG. 6 shows a cement sampling feature.

DETAILED DESCRIPTION

FIG. 1 shows a well bore or bore hole 110 that has been bored into theground 100. A bore-lining tubing in the form of a casing 20 extends froma wellhead 34 into the bore hole 110 and defines an annulus 50 betweenthe outside of the casing 20 and the earthen walls of the bore hole 110.As described later, this annulus 50 will be filled, either partially orin full, with a settable material 54 (shown in FIG. 2), such as a cementslurry, which will set in due course to form solid walls of the borehole 110 to, for example, prevent the bore hole 110 from collapsing,protect and support the casing 20, and prevent fluid from withinpermeable formations 66 (FIG. 4) flowing up within the annulus 50.

A casing and liner are structurally very similar and may be made usingidentical piping. In the oil and gas exploration and extractionindustry, a casing 20 refers to bore-lining tubing that extends from thewellhead 34 towards the base of the bore hole 110. A liner may extendonly part of the way through the bore hole 110. Thus, a liner may besuspended from, for example, a casing section or another liner, ratherthan being connected to the wellhead 34. The term casing will be usedpredominantly herein but it should be understood that the belowdescription is also applicable to a liner.

The drawings show only a single casing string 20, and this first casingis often referred to a “conductor”. A conductor will typically have arelatively large outer diameter, for example 30 to 36 inches (76.2 to91.4 cm), and an inner diameter of 28 to 33 inches (71.1 to 83.8 cm). Asdiscussed herein, the disclosure is equally applicable to smallersubsequent casings which will locate with the conductor, and to liners.

An inner tubing in the form of a work string 10 extends down the insideof the casing 20. The work string 10 connects at a first or upper end 14to a running tool 30 that is removably installed in the wellhead 34 thatis located on the surface of the ground, or seabed, into which the borehole 110 is drilled. The running tool 30 may engage with a casing hangerprovided at the upper end of the casing. Alternatively, the running tool30 and work string 10 may extend within a liner hanging from a linerhanger provided, for example, within the casing 20. A suitable runningtool is available from OneSubsea, part number 2143701-48.

The second or lower end of the work string 10 includes a latching orstab-in connector 68 that is adapted to connect to a work or float shoe22 that forms or connects to the base portion of the casing 20. Asuitable shoe 22 is supplied by Forum Energy Technologies (Double valvelatch-in float shoe with latch-down receptacle for latch-down plug, Type500DVLLP-PVTS), and a suitable connector 68 is the Latch-in Adapter,Type B—133, 3″, also supplied by Forum Energy Technologies, but modifiedby provision of three DOT Rupture ports to provide the valve 12 a asdescribed below.

In another example, rather than connecting to the shoe 22, the secondend 16 of the work string 10 may connect to another piece near the baseof the casing 20, for example a coupling provided in the casing 20 abovethe float shoe 22. In general, the work string 10 may extend from therunning tool 30 to a lower portion of the casing 20.

The work string 10 may be generally in the form of a pipe or a conduitthat is able to convey fluid pumped from surface through the runningtool 30 to the work shoe 22, and in this example a major portion of thestring 10 is formed of drill pipe. Other tubular body portions includingvalves, seats, special couplings and the like may be provided within thework string 10. The drill pipe will typically have an outer diameter of5½ inches (14 cm) and the sections of tubing incorporating valves,couplings and the like may have an outer diameter of 6 inches (15.2 cm).The work string 10 is coaxial with the casing 20 and thus the outersurface of the work string 10 and inner wall of the casing 20 define aninner or second annulus 52.

The work string 10 also comprises flow ports provided with respectivevalves 12 a, 12 b and 12 c that selectively allow fluid communicationbetween the inside of the work string 10 and the outside, for examplesuch that fluid may flow from the interior of the work string 10 andinto the second annulus 52. As described in more detail later, thevalves 12 a, 12 b, 12 c are initially closed while the settable material54 is being pumped into the first annulus 50.

The work shoe 22 has a flow port or aperture 24 through which thesettable material 54, conveyed from surface and down through the workstring 10, may travel to the annulus 50 outside the casing 20. The flowport 24 may also include two float valves, one-way valves which preventreverse flow of cement slurry back into the work string 10. After thedesired volume of settable material 54 has been pumped into the annulus50, the aperture 24 may be plugged and sealed, for example with a ballor dart 44 (see FIG. 3) to prevent further flow of fluid from the workstring 10 into the annulus 50. The sealing dart 44 may be delivered fromthe surface, down a running or landing string 42, down the work string10, and into the aperture 24, moving, for example, under cementdisplacement fluid pressure from surface pumps.

At or above the wellhead 34, the running tool 30 may connect to arunning or landing string 42 that supports the casing 20 and work string10 and extends to a source 40 of the settable material 54. The runningtool 30 provides fluid communication from the landing string 42 to thework string 10 and seals the upper end of the casing 20, closing theupper end of the inner annulus. The source 40 may be, for example, a rigor ship on the sea surface in the case of an undersea bore hole 110, andin this example will include cement mixing and pumping facilities, andfacilities for heating and pumping a second fluid such as water.Alternatively, the source 40 may be a drilling installation on theground, in the case of a surface bore hole 110.

The casing 20 may be made up on the rig and may be run partially intothe bore hole 110. With the upper end of the casing 20 supported at thedeck of the rig, the work string 10 is then made up and run into thecasing 20. The lower end of the work string 10 is provided with alatching or stab-in connector 68 and a telescopic coupling 70 whichallows selective transfer of torque between upper and lower parts of thestring 10. When axially extended the coupling 70 allows transfer oftorque through the coupling 70 via an internal spline arrangement. Whenretracted by compression the spline arrangement is disengaged and thecoupling 70 does not transfer torque and the upper part of the string 10may rotate relative to the lower part of the string 10.

The running tool 30 is coupled to the upper end of the work string 10and the running string 42 is coupled to the running tool 30. With thetelescopic coupling 70 fully extended, the running tool 30 is positioneda short distance above the upper end of the casing 20 and the lower endof the work string 10 is positioned a short distance above the casingshoe 22. The running string 42 is then lowered to stab the work stringconnector 68 into the casing shoe 22. Lifting the running string 42 willconfirm if the work string 10 is properly engaged with the shoe 22.After the second annulus 52 has been top-filled with fluid the runningstring 42 is then lowered further to engage the running tool 30 with theupper end of the casing 20. By rotation of the running string 42, a maleleft-handed thread on the running tool 30 engages a corresponding femalethread on the casing 20, providing a secure and fluid-tight connectionbetween the running tool 30 and the casing 20. The compression of thetelescopic coupling 70 achieved by lowering of the running string 42ensures that the rotation of the running string 42 and the running tool30 does not result in corresponding rotation of the lower end of thework string 10. The assembly is then lowered from the rig, supported bythe running string 42, to the position as illustrated in FIG. 1.

In operation, as shown in FIG. 2, the source 40 pumps the settablematerial 54 through the landing string 42 and into the work string 10(in the direction of arrows 56). The settable material 54 flows from thefirst end 14 to the second end 16 of the work string 10 and into theaperture or first flow port 24 in the work shoe 22. The flow ports inthe work string 10 provided with the valves 12 a, 12 b, 12 c are closedat this point. The settable material 54 flows through the open aperture24 into the first annulus 50 and fills the annulus 50. The settablematerial may be of a consistent composition or may comprise parts ofdifferent compositions and properties. For example, the lead slurry 54 amay have a different composition from the tail slurry 54 b.

Once the annulus 50 is filled with the settable material 54, the sealingdart 44 for landing in the aperture 24 is placed in the landing string42 and, following an additional volume of settable material, a wiperdart is placed in the string 42. The settable material flowing into thestring 42 is then stopped and replaced by a flow of a second fluid,typically water. The dart 44 and the wiper dart travel down through thelanding string 42 and the work string 10. On reaching the lower end ofthe work string 10 the dart 44 lands in and closes the aperture 24 , asshown in FIG. 3.

As shown in FIG. 4, the valve 12 a in the work string 10 may be openedat this stage and the water being pumped from the source 40 through thelanding string 42 and into the work string 10 (in the direction ofarrows 58) will flush out any residual settable material 54 from thestrings 42, 10 into the second annulus 52. This flushing may becontinued for an extended period through a valve 32 on the running tool30 that may allow fluid (for example a mixture of the second fluid andthe residual settable material 54) to exit the second annulus 52 via thevalve 32 (in the direction of arrow 60). In one example, the valve 32 isa ball-valve that is selectively and temporarily opened or closed byadjusting the rate of fluid flow or applying a greater fluid pressure bythe source 40, down the work string 10, and into the second annulus 52.Alternatively, the valve 32 is selectively and temporarily opened orclosed by simple intervention by a human or a robot, such as an ROV.

After or instead of the flushing process, the valve 32 allows forpressure testing of the new borehole walls formed by the casing 20 andthe settable material 54. In this pressure testing process, the valve 32in the running tool 30 is kept closed and a second fluid such as wateris pumped from the source 40 into the second annulus 52 inside thecasing 20. This increases the pressure on the inner wall of the casing20. The observed increase in pressure and/or rate of increase inpressure (which may be monitored at or near the source 40) may becompared to an expected increase in pressure (or rate of increase inpressure, as appropriate).

Pressure testing may be performed while the settable material 54 isstill unhardened or “green” (e.g. still liquid). During pressuretesting, the casing 20 will generally expand outwards (“balloon”) underthe pressure from the second fluid. When the pressure is relieved, thecasing 20 may then relax back to its original shape. In the case wherethe settable material 54 has not yet hardened, the settable material 54will first be moved by the ballooning outward of the casing 20 and willthen flow back when the casing 20 returns to its original shape. Thisflow may reduce the formation of weak-points which would occur if thefluid had already hardened and is then pushed away (or crushed) by theballooning casing 20 and does not return after the ballooning subsides,creating a micro-annulus and compromising the hydraulic sealingcapabilities of the setting material.

Further, the pressure testing, and the accompanying relative movementbetween the outer surface of the casing and the settable material 54,may improve adhesion between the casing 20 and the settable material 54.

During the pressure testing, if the observed increase in pressure is notas expected, this may indicate a leak in the casing 20. In this case,the valve 32 in the running tool 30 may be temporarily opened and athird fluid may be pumped into the second annulus 52 to displace thesecond fluid. The third fluid may be a drilling fluid or “mud”, which isan engineering composition formed from of a fluid (e.g. water or oil)with particulate matter suspended therein. During pressure testing withthe third fluid, the particulate matter from the drilling mud may fillsmall cracks in the casing 20 or gaps at connections between casingsections, to adequately repair the casing 20 and demonstrate the casing20 has pressure-retaining integrity.

The fluid pumped into the second annulus 52 following the settablematerial 54 may be at a temperature selected to modify the hardening orcuring of the settable material 54. For the bulk of cement slurriesemployed in the oil and gas exploration and extraction industry,typically comprising Portland cements, an increase in temperature willresult in accelerated hardening, while a decrease in temperature willretard hardening.

In many cementing operations the most important portion of cement isthat surrounding the lower end of the casing, as created by the tailslurry 54 b. During a subsequent drilling operation, the casing shoe 22and any cement in the bore 110 beyond the shoe 22 will be removed bydrilling, and during this operation the casing 20, and the surroundingcement 54 b, will experience shocks and vibration from the rotatingdrill bit. In many instances it is therefore the condition of thisvolume of cement 54 b that is critical before further drilling may takeplace.

In most bore drilling operations, the temperature of the surroundingearth formations will increase with increasing depth. Accordingly, thecement slurry 54 b towards the lower end of the bore 110 will likelyexperience higher temperatures than the cement slurry 54 a towards theupper end of the bore 110. However, the earth formations may have beenpreviously cooled by the circulation of flushing or cleaning fluidthrough the annulus 50 in preparation for cementing, and the cementslurry 54 may itself have been cooled as it is pumped from surfacethrough the running string 42 and work string 10. In offshoreoperations, this may involve passage of the cement slurry 54 throughthousands of meters of cold sea water.

In accordance with an example of the present disclosure the second orconditioning fluid may be heated at surface before being pumped into thebore 110, such that the fluid is relatively hot when it flows out of theopen valve 12 a and into the second annulus 52 between the work string10 and the casing 20. The heated fluid will warm the casing 20 whichwill in turn warm the surrounding cement slurry 54, thus acceleratinghardening of the cement.

By supplying the heated fluid into the second annulus 52 via thelowermost valve 12 a, the maximum heating effect will be achieved at thelower end of the bore 110, but the heated fluid will continue tocirculate up through the second annulus 52 and will heat theintermediate and upper portions of the casing 20, and the surroundingcement slurry 54. Thus, the cement 54 in the first annulus 50 willharden more quickly than if no fluid, or unheated fluid had been pumpedinto the second annulus 52. The operator may supply a volume of heatedfluid sufficient only to heat a lower portion of the bore, or may supplya larger volume of fluid, perhaps pumped at a higher rate, sufficient toheat the entire casing 20.

By way of example, in an offshore location such as the North Sea with asea depth of 500 metres or greater, the temperature on surface may be10° C., and the temperature at the sea bed may be 5° C. The settablematerial 54 prepared at surface will have an initial temperature ofaround 10° C. but will be cooled as the material 54 is pumped from therig, through the cold sea water. The settable material will then bewarmed as it passes down through the well bore and into the firstannulus 50, where the material will likely be at a temperature of around15° C. At this temperature, the time taken for the static gel strength(SGS) of cement to reach or exceed 500 lbf/100 sq. ft (240 Pa) is 10 to12 hours. However if, in accordance with an example of the presentdisclosure, conditioning water is heated on the rig to 85° C. and pumpedinto the well bore, and circulated through the second annulus 52 at aflow rate of 20 bbls/min (53 litres/second), the temperature within thewell bore may be raised to 40° C., at which temperature the time takenfor the static gel strength (SGS) of cement to reach or exceed 500lbf/100 sq. ft (240 Pa) is 1 to 2 hours. Accordingly, by providing aflow of heated conditioning fluid the setting time of the cement is verysignificantly reduced, allowing operations to continue much sooner thanwould have been the case if no heated fluid was provided. In addition,the elevated temperatures in the well bore result in set cement withmuch higher compressive strength.

In shallower water it is not necessary to heat the conditioning fluid tosuch a high temperature. For example, in similar conditions to thosedescribed above, but where the water depth is less than 100 metres,achieving a target temperature of 40° C. at cement placement depth maybe achieved by heating the conditioning fluid to a temperature of 50° C.Conversely, in very deep or very cold water it may be difficult toachieve a temperature of 40° C. at cement placement depth, however anyincrease in temperature in the well bore will accelerate cement settingand improve cement quality. For any given situation the operator maybalance the costs of heating conditioning fluid to a higher temperatureand pumping the heated fluid into the bore hole with the correspondingreduction in cement setting time, and the better quality of the setcement. However, with even a relatively small increase in temperature(c5° C.) capable of providing a 20 to 40% reduction in setting time,pumping heated conditioning fluid into the bore hole will provide asignificant advantage in many circumstances.

In other situations, it may be considered desirable to acceleratehardening of the settable material 54 only at a selected location in thebore 110, for example where the bore intersects a permeable formation66, which may be a high-pressure fluid-producing formation or a lowpressure formation. For some cement slurries, the slurry may becomeresistant to passage of fluid through the cement when the gel strengthreaches a particular level. Accordingly, it may be desirable for thecement slurry 54 c adjacent the formation 66 to reach this gel strengthrelatively quickly, which may be achieved by increasing the temperatureof the slurry 54 c. However, until the gel strength reaches this levelit may be desirable that the gel strength of the slurry 54 a above theformation 66 remains at a lower level, such that the slurry 54 acontinues to provide a hydrostatic head that retains the fluid in theformation 66 while the slurry 54 c in contact with the formationhardens.

With the present apparatus, the selected location in the bore 110 may betargeted by opening the valve 12 b in the inner string 10 adjacent thefluid-producing formation 66, such that the heated fluid enters thesecond annulus 52 adjacent the formation 66 which the operator wouldprefer to harden relatively quickly. Alternatively, or in addition, theoperator may select to retard the setting of the cement slurry 54 aabove the formation 66, in which case cooled or cooler fluid may bedirected into the second annulus 52 via an upper valve 12 c.

Similarly, an operator may select to protect a low-pressure formation byaccelerating hardening of cement slurry adjacent the formation.

Alternatively, the operator may pump heated fluid through the lowermostvalve 12 a at a very particular engineered flow rate, slow enough toallow the fluid to dissipate its heat as the fluid rises up through thesecond annulus 52 and create a large temperature gradient and controlthe rate at which the setting material goes through the transition zone(100-500 lbs/100 ft² of static gel strength) at different locations inthe bore. In effect, the operator may control the volume and location ofsettable material going through the transition zone at any point intime.

In another situation the operator may wish the slurry 54 a at the upperend of the bore 110 to harden relatively quickly, for example to allowmounting of heavy subsea apparatus, such as a blow-out preventer (BOP),on the upper end of the casing 20. In this situation the operator maydirect heated fluid through an upper valve 12 c, to accelerate settingof the slurry 54 a in the upper end of the annulus 50.

There may also be situations in which the operator wishes to restrict oravoid rises in temperature at selected locations. For example, in deepsea operations the sea bed may contain hydrates, molecules of naturalgas bonded to frozen water molecules. If the temperature of the earthrises the gas molecules may be liberated, potentially leading tocollapse of the heated area and uncontrolled release of large volumes offlammable gas. Setting cements may generate heat during hydration, andif left unchecked the resulting temperature rise in the surroundingearth may result in the release of gas. Accordingly, an operator mayutilize the apparatus described above to direct fluid through the uppervalve 12 c into the upper portion of the second annulus 52, which fluidmay cool the casing 20 and the adjacent cement slurry 54 a, and thusavoid or reduce heating of the surrounding earth.

The valves 12 a, 12 b, 12 c may be opened and closed in any desiredsequence, and thus heated or cooled fluid may be supplied to selectedbore locations to influence or control the setting of the material 54 inthe annulus 50. In some examples it may not be necessary to heat or coolthe fluid, as ambient temperature fluid may provide the desiredconditioning.

Control of the valves 12 a, 12 b, 12 c may be achieved by anyappropriate mechanism, for example by pumping RFID tags into the innerstring, which tags activate a selected valve to open or close.Alternatively, an operator may open and close the valves using darts orballs pumped into the inner string 10.

In some examples the operator may pump conditioning fluid into the wellbore 110 to control or manage the thermal expansion or contraction ofthe bore-lining tubing 20. This may be to limit differential thermalexpansion and contraction between the tubing 20 and the settablematerial, for example as induced by the heat of hydration of a settingcement. In another example the operator may maintain the temperature ofthe bore-lining tubing 20 below the ambient temperature of the well bore110 until the settable material 54 has hardened. Once the material 54has hardened, the temperature of the tubing 20 may be allowed to rise tothe ambient well bore temperature, accompanied by thermal expansion ofthe tubing 20, which urges the outer surface of the tubing 20 intotighter contact with the inner surface of the set material 54. This“pre-loads” the set material 54, eliminating potential micro-annuli.

Conditioning fluid may be circulated into the annulus 50 before thesettable material 54 is delivered into the well bore 110, to cool thewalls of the well bore 110 and cool the bore-lining tubing 20.Conditioning fluid may be delivered to the annulus 50 via the workstring 20 and through a first flow port, such as the aperture 24.Following the filling of the annulus 50 with settable material 54,conditioning fluid may be circulated through the second annulus 52 and asecond flow port, such as the first valve 12 a. Depending on the wellbore conditions, the operator may choose to cool the conditioning fluidbefore delivering the fluid downhole, or it may be sufficient tocirculate conditioning fluid that is at surface ambient temperature. Asnoted in the examples above, if conditioning fluid is delivered from arig or ship through deep water the conditioning fluid will be cooled asit travels between the sea surface and the sea bed, and the fluid willstill be relatively cool when it reaches the portion of the well borecontaining the bore-lining tubing. A varying degree of cooling may beachieved by varying the flow rate of the conditioning fluid.

The conditioning fluid may be selected to have a relatively low density,such that the hydrostatic fluid pressure created by the column of fluidwithin the bore-lining tubing 20 remains relatively low and does nottend to balloon the bore-lining tubing outwards, or otherwise distortthe casing 20, as the gel strength of the settable material 54 increasesand the hydrostatic fluid pressure in the outer annulus 50 decreases.This facilitates the creation of a secure bond between the outer surfaceof the casing and the inner surface of the set material 54.

After any pressure testing, flushing, or cement conditioning, the workstring 10 may be removed from the casing 20, as shown in FIG. 5. This isachieved by rotating the running string 42 to disengage the running tool30 from the upper end of the casing 20. This may also cause activationof external seals provided on a casing hanger at the upper end of thecasing 20. The running string 42 and running tool 30 are then raised toplace the work string 10 in tension and extend the coupling 70. Rotationof the running string 42 may then be transferred to the lower end of thework string 10, permitting the connector 68 at the lower end of thestring 10 to be unscrewed from the shoe 22. If the operator is unable tounscrew the work string 10 from the shoe 22, an overpull may be appliedto shear out the string 10 from the casing 20.

The casing 20 and hardened fluid 54 remain in the borehole 110 toprovide solid walls for the borehole 110 to prevent collapse and toprovide a fluid-tight seal from the wellhead 34 to the work shoe 22.Thereafter, the bore 110 may be drilled further (which will involvedrilling out the shoe 22 and any set cement below the end of the casing20), to allow location of a further casing or liner, or an alternativeapparatus may use the borehole 110, such as a pipe for conveying oil ornatural gas from beneath the borehole 110 to a rig (not shown) at orabove the wellhead 34.

In one example, at least one of the valves 12 a, 12 b, 12 c is a sheardisc that is designed to shear at a designated pressure differencebetween the fluid inside of the work string 10 and the fluid outside thework string 10. In this case, the settable material 54 is pumped at apressure such that the shear disc does not shear during cementplacement. After the settable material 54 has been displaced to fill thefirst annulus 50 and the aperture 24 in the work shoe 22 has beenclosed, the second fluid may be pumped into the work string 10 at apressure above the pressure required to shear the shear disc. This opensthe valve 12 and allows the second fluid (and any residual first fluid)to be flushed through the work string 10 and into the second annulus 52and, optionally, out through the valve 32 in the running tool 30.

The lower valve 12 a may be provided with a shear disc that fails at afirst pressure, such that the second fluid is initially flowed throughthe valve 12 a. If the operator wishes to direct fluid to anotherportion of the bore a valve-closing sleeve may be pumped into the workstring 10 to close the valve 12 a and then the pressure in the string isincreased to burst a disc in another of the valves 12 b, 12 c.

Alternatively, only a single valve location may be provided on the workstring 10. If desired the operator may direct conditioning fluid into aselected location in the annulus 52 by disengaging the work string 10from the shoe 22 and raising the open valve to the desired location inthe bore 110.

Reference is now also made to FIG. 6 of the drawings, which illustratesa cement sampling feature in accordance with a further example of thepresent disclosure. In the example described above, once the annulus 50is sufficiently filled with the settable material 54, the aperture 24 inthe work shoe 22 is closed with a dart 44, as shown in FIG. 3. Thus,when the connector 68 is disengaged from the casing shoe 22 the lowerend of the work string 10 is open. However, in the example of FIG. 6,rather than a dart 44 landing in the shoe 22, the flow passage betweenthe lower end of the work string and the first annulus is closed bylanding a ball 144 in a ball seat 146 provided in the connector 168. Inboth examples the lowermost inner string valve 12 a, 112 a is providedin the connector body 148, however in the example of FIG. 6 theconnector body 148 is extended to provide a generally cylindrical samplevolume 150 between the ball 144 and the valve 112 a.

The ball 144 may be dropped into the work string after a desired volumeof cement slurry 170 has been pumped into the first annulus. An operatorwill always prepare and pump an excess volume of cement slurry such thata column of cement slurry will remain in the lower end of the workstring. The ball 144 may thus move downwards through this column ofslurry and land on the ball seat 146. If desired, a larger second ballmay be dropped into the work string and land on another ball seat justbelow the valve 112 a.

When the valve 112 a is opened, for example by pressuring up the workstring and bursting a shear disc in the valve 112 a, the column ofcement slurry in the work string above the valve 112 a will be pushedthrough the valve 112 a and into the second annulus, followed by adisplacement or flushing fluid. As discussed above with reference to theprevious example, the operator may also choose to pressure test thecemented casing and circulate heated or cooled conditioning fluidthrough the second annulus to control the setting of the cement.

During these operations the volume of cement slurry 170 above the ball144 and below the valve 112 a will remain in the connector 168 and willbegin to harden in a similar manner to the cement in the first annulus150. For example, if the operator is supplying heated conditioning fluidthrough the valve 112 a the setting of the cement slurry sample will beaccelerated.

When it is desired to retrieve the work string from the well bore, thestring is placed in tension and rotated from surface to unscrew theconnector 168 from the casing shoe. When the connector 168 and the shoeseparate, and as the work string is tripped out to the surface, thecement sample 170 is retained in the connector 168 by the ball 144.

On reaching the surface, the set cement sample 170 may be removed fromthe connector 168. This operation may be facilitated by forming theconnector 168 of separable parts, or by providing a low friction sleevewithin the connector 168 for containing the sample 170 and which may beeasily removed from the connector 168.

The cement forming the sample 170 will have experienced similarconditions to the cement in the first annulus and thus will provide amore accurate indication of the condition of the cement in the annulusthan a sample of cement slurry taking at surface and allowed to setunder ambient surface conditions.

Although the methods and apparatus have been described in terms ofparticular examples as set forth above, it should be understood thatthese examples are illustrative only and that the claims are not limitedto those examples. For example, it will be apparent to the skilledperson that the apparatus and methods may be utilized in bore holescreated for other purposes, for example injection wells, wells foraccessing aquifers, and geothermal wells. Those skilled in the art willbe able to make modifications and alternatives in view of the disclosurewhich are contemplated as falling within the scope of the appendedclaims.

1.-38. (canceled)
 39. A downhole method comprising: pumping a settablematerial into a bore and into an annulus between bore-lining tubing anda wall of the bore, the annulus having a first axial portion and asecond axial portion and whereby the settable material fills the firstaxial portion and the second axial portion; and affecting thetemperature of the settable material in the first axial portion of theannulus whereby a setting rate of the first axial portion is differentfrom a setting rate in the second axial portion.
 40. The method of claim39, wherein the first axial portion of the annulus is located below thesecond axial portion of the annulus whereby the settable material in thefirst axial portion is located below the settable material in the secondaxial portion.
 41. The method of claim 39, wherein the first axialportion of the annulus is located above the second axial portion of theannulus whereby the settable material in the first axial portion islocated above the settable material in the second axial portion.
 42. Themethod of claim 39, further comprising heating the settable material inthe first axial portion of the annulus such that the setting rate of thesettable material in the first axial portion is faster than the settingrate of the settable material in the second axial portion and thesettable material in the first axial portion of the annulus sets beforethe settable material in the second axial portion of the annulus. 43.The method of claim 39, further comprising cooling the settable materialin the first axial portion of the annulus such that the setting rate ofthe settable material in the first axial portion is slower than thesetting rate of the settable material in the second axial portion andthe settable material in the first axial portion of the annulus setsafter the settable material in the second axial portion of the annulus.44. The method of claim 39, further comprising pumping conditioningfluid into the bore.
 45. The method of claim 44, further comprisingpumping the conditioning fluid into the bore before pumping the settablematerial into the bore.
 46. The method of claim 44, further comprisingpumping the conditioning fluid into the bore after pumping the settablematerial into the bore.
 47. The method of claim 44, further comprisingpumping the conditioning fluid into the bore to cool the bore.
 48. Themethod of claim 44, further comprising pumping the conditioning fluidinto the bore to warm the bore.
 49. The method of claim 44, furthercomprising pumping the conditioning fluid into the bore to maintain thebore at a predetermined temperature.
 50. The method of claim 44, furthercomprising pumping the conditioning fluid into the annulus between thebore-lining tubing and the wall of the bore.
 51. The method of claim 44,further comprising pumping the conditioning fluid through an innertubing within the bore-lining tubing.
 52. The method of claim 51,further comprising pumping the conditioning fluid into an inner annulusbetween the inner tubing and the bore-lining tubing.
 53. The method ofclaim 52, further comprising pumping the conditioning fluid into a firstaxial portion of the inner annulus to affect the temperature of thesettable material in the first axial portion of the annulus.
 54. Themethod of claim 52, further comprising pumping the conditioning fluidinto a second axial portion of the inner annulus to affect thetemperature of the settable material in the second axial portion of theannulus.
 55. The method of claim 52, further comprising: opening a firstfluid port in the inner string; pumping the conditioning fluid from theinner string through the first fluid port into a first axial portion ofthe inner annulus to affect the temperature of the settable material inthe first axial portion of the annulus; closing the first fluid port andopening a second fluid port in the inner string and then pumping theconditioning fluid from the inner string and through the second fluidport into a second axial portion of the inner annulus to affect thetemperature of the settable material in the second axial portion of theannulus.
 56. The method of claim 39, wherein: the first axial portion ofthe annulus is located below the second axial portion of the annuluswhereby the settable material in the lower first axial portion islocated below the settable material in the upper second axial portion;the settable material in the annulus has a static gel strength whichincreases as the settable material transitions from an initial fluidform to a solid form, and the settable material has atemperature-related setting rate; the method further comprising: pumpinga conditioning fluid into the bore-lining tubing at an operator-selectedflowrate and an operator-selected temperature, at least one of theconditioning fluid flowrate and the conditioning fluid temperature beingselected to increase the setting rate of the settable material in thelower first axial portion of the annulus relative to the setting rate ofthe settable material in the upper second axial portion of the annuluswhereby the static gel strength of the settable material in the lowerfirst axial portion of the annulus reaches 500 lbf/100 sqft while thestatic gel strength of the settable material in the upper second axialportion of the annulus remains below 500 lbf/100 sqft.
 57. A downholemethod comprising: pumping a settable material in fluid form into anannulus between bore-lining tubing and a bore wall, the annulus having alower first axial portion and an upper second axial portion and wherebythe settable material fills both the lower first axial portion and theupper second axial portion, the settable material in the annulus havinga static gel strength which increases as the settable materialtransitions from the fluid form to a solid form and the settablematerial in the annulus having a temperature-related setting rate; andpumping a conditioning fluid into the bore-lining tubing at anoperator-selected flowrate and an operator-selected temperature, atleast one of the conditioning fluid flowrate and temperature beingselected to increase the setting rate of the settable material in thelower first axial portion of the annulus relative to the setting rate ofthe settable material in the upper second axial portion of the annuluswhereby the static gel strength of the settable material in the lowerfirst axial portion of the annulus reaches 500 lbf/100 sqft while thestatic gel strength of the settable material in the upper second axialportion of the annulus remains below 500 lbf/100 sqft.
 58. An apparatuscomprising: a tubular body for mounting on an inner tubing string; afirst distal flow port; a second intermediate flow port; a thirdproximal flow port, the first distal flow port, second intermediate flowport and third proximal flow port being provided at axially spacedlocations; and a connector operatively associated with the tubular bodyand operable to engage with a lower end of a bore-lining tubing stringand then subsequently disengage from the lower end of the bore-liningtubing, the apparatus having first, second and third configurations, inthe first configuration the connector is engaged with the lower end ofthe bore-lining tubing string, the first distal flow port is open andthe second intermediate flow port and third proximal flow port areclosed, whereby a settable material may be pumped in a first directiondownwards through the tubular body, the connector, and the first distalflow port, in the second configuration the first distal flow port andthe third proximal flow port are closed and the second intermediate flowport is open, such that the apparatus is adapted to allow a conditioningfluid to be pumped in the first direction down through the tubular body,through the second intermediate flow port, and then flow in a seconddirection upwards and externally of the tubular body, and in the thirdconfiguration the first distal flow port and second intermediate flowport are closed and the third proximal flow port is open such that theapparatus is adapted to allow a conditioning fluid to be pumped in thefirst direction down through the tubular body, through the thirdproximal flow port, and then flow in a second direction upwards andexternally of the tubular body.